1. CO₂ Capture from SMR type flue gas using CESAR1 solvent at Technology Centre Mongstad (2022)

Sundus Akhter^a*, Ahmad Wakaa^a, Anette Knarvik^a,b, Erik Gjernes^c, Ida M. Bernhardsen^b, Muhammad I. Shah^a,c

aTechnology Centre Mongstad, 5954 Mongstad, Norway bEquinor ASA, PO Box 8500, 4035 Stavanger, Norway cGassnova SF, Dokkvegen 11, 3920 Porsgrunn, Norway

Abstract

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The Technology Centre Mongstad (TCM DA) in Norway has investigated the CO₂ capture performance with the non-proprietary CESAR1 solvent for flue gases with CO₂ concentration like that of a SMR (steam methane reforming) furnace. The basis for this investigation is Equinor’s SMR unit at Tjeldbergodden methanol plant. Specific reboiler duty (SRD) is reported for 90% CO₂ capture from flue gases with 10 and 15 vol% (dry) CO2 content when using 12 and 18 m absorber packing height. Tests at 10 vol% (dry) CO₂ content confirmed that SRD levels below 4 GJ/ton CO₂ are achievable with only 12 m absorber packing height, but lower SRD values are achieved with 18 m absorber packing height. This illustrates that a more compact absorber will give lower CAPEX at the expense of a higher heat requirement for the CO₂ stripper. During the tests, precipitation was observed in the absorber packing despite that the overall absorber condition were unfavorable for this to occur. Also, foaming in stripper was observed and mitigated by the use of anti-foam.

1.  Introduction

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The Technology Centre Mongstad (TCM DA), established in 2012, is one of the world’s largest facilities to test, verify and demonstrate different post combustion carbon dioxide capture (PCC) technologies. The company is a joint venture between Gassnova (the Norwegian state), Equinor, Shell and Total Energies with a common vision to facilitate development of carbon capture and storage (CCS) for the wide deployment of large-scale carbon capture technologies across industries. The facility is located next to the Equinor refinery in Mongstad providing two types of flue gas sources: (1) combined cycle gas turbine (CCGT) based heat and power plant flue gas (CHP) and (2) residual fluid catalytic cracker (RFCC) flue gas. The different flue gas sources enable TCM to mimic flue gases from different industries such as waste incineration, gas processing, steam reforming and oil refining.

Since the start-up in 2012, TCM has gained valuable knowledge and experience with the use of the non-proprietary solvents monoethanolamine (MEA) and CESAR1 for CO₂ capture. CESAR1 is a blend of 27 wt% 2-Amino-2- methylpropanol (AMP) and 13 wt% piperazine (PZ) and is considered to be a better solvent than MEA in terms of

thermal energy and stability [1,2]. CESAR1 was first tested at TCM as a part of the ALIGN-CCUS campaign in 2019 where the energy demand was found to be around 10% lower than that of 30 wt% MEA. Although the comparison is not straightforward, the tests provided valuable learnings with this solvent [3,4]. To further explore the solvent’s potential, the owners of TCM DA performed two campaigns with CESAR1 from April to December 2020. The goal of the campaigns was to carry out long term operation with this solvent, close knowledge gaps on the solvent performance with different flue gas compositions, to understand cost reduction potential of CO₂ capture with CESAR1 and perform thermal reclaiming [5] of the solvent.

This paper presents results from the part of the CESAR1 owner’s campaign which was carried out to understand the CESAR1 solvent’s potential for CO₂ capture from steam methane reformer (SMR) flue gas. Steam methane reforming is a key technology for converting natural gas to synthesis gas and is the dominant technology for hydrogen production. In this work, the CO₂ concentration was varied from 10 to 15 vol% (dry). The CO₂ concentration of 10 vol% mimic the SMR flue gas at the Equinor methanol plant at Tjeldbergodden [6]. The methanol plant at Tjeldbergodden is the largest in Europe. It produces approximately 900,000 tonnes of methanol per year and accounts for around 25% of total European methanol production. The methanol is produced using natural gas and pure oxygen as raw material. Natural gas is converted to synthesis gas by combined reforming (i.e. steam methane reforming followed by autothermal reforming) and the resulting synthesis gas is converted to methanol. Currently, the methanol plant at Tjeldbergodden emits around 300,000 tonnes CO2 per year. As most of this CO2 is generated in the SMR furnace by combustion of fuel, there is a considerable potential for CO₂ reduction. The fuel combusted in the SMR is a mixture of natural gas and purge gas from the synthesis gas, and the composition of the SMR flue gas will depend on the purge gas rate, and composition of the natural gas.

The first part of this paper presents the energy performance obtained with the CESAR1 solvent when varying the CO₂ concentration, absorber packing height and flow rates, while maintaining 90% CO₂ capture. The second part of the paper describes operational experiences with CESAR1 solvent at TCM.

2.  Assessment of CESAR1 performance with SMR flue gas

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2.1 TCM amine plant description

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Figure 1 shows a simplified illustration of the TCM amine plant in CHP mode. Flue gas from the blower is conditioned and saturated with water to the required temperature (normally 20-50 °C) in the direct contact cooler (DCC). CO₂ is captured in the absorber by the lean amine flowing downwards counter current with the flue gas. The depleted flue gas passes through two water wash stages before being emitted to the atmosphere. Rich amine from the absorber is pumped through the rich/lean cross plate heat exchanger to the stripper where the CO₂ is released using a steam-heated reboiler. The lean amine is then pumped back to the absorber.

The plant is flexible and offers the possibility to test several different configurations and a wide range of flue gas flow rates and compositions. Two strippers are available with capacities up to about 3,500 and 8,000 kg CO₂/h. The latter, named RFCC stripper, was in operation during the present test program. The lean amine solvent can be fed at various solvent flow rates utilizing 12, 18 or 24 m of the absorber structured packed bed (highlighted in yellow in Figure 1). The CO₂ content in the flue gas can be increased by recycling captured CO₂ to DCC inlet. A more detailed description of the amine plant is available elsewhere [7,8].

2.2 CESAR1 campaign mimicking SMR flue gas

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The three phases A, B and C of the test program are presented in Table 1. The plant was operated to capture 90% CO₂ from a flue gas with 10 to 15 vol% (dry) CO₂, i.e. mimicking SMR flue gas. For each phase, the objective was to determine the optimal specific reboiler duty (SRD) by varying the solvent circulation rate.

The tests in Phase A were performed at 18 m absorber packing height to find the lowest possible SRD. In phase B, the packing height was reduced to 12 m. This was made to illustrate the consequence of utilizing a more compact absorber that reduces CAPEX at the expense of increased heat requirement and OPEX. During phase C, tests were conducted at 18 m and at a higher CO₂ concentration to better understand the impact of flue gas CO₂ concentration at a target capture rate of 90%. All tests were made with CHP flue gas including CO₂ recycling and with the RFCC stripper in operation. CO₂ recycling increased the CO₂ content in the flue gas into the absorber from about 4 to 10 and 15 vol% (dry). The target CESAR1 solvent concentration during the campaign was 40 wt% comprising 27 wt% AMP and 13 wt% Piperazine. This concentration was similar as used in the previous ALIGN-CCUS campaign at TCM [4], however, variations occurred both in total amine concentration and Piperazine and AMP ratio. Calibration and validation of analysers were carried out before and during the campaign to ensure good data quality on solvent performance and compliance with emission permit.

Table 1 Operational parameters for tests mimicking SMR flue gas.

¹Captured CO₂ for test A5, B7* and C7.

The amount of CO₂ being captured can be calculated based on either the mass balance over the absorber; i.e. CO₂ in versus CO₂ out of the absorber or on the CO₂ mass flow out of the stripper. The results presented here are based on the latter. The CO₂ capture rate is then calculated as mass flow of captured CO₂ versus the CO₂ mass flow into the absorber. SRD is calculated based on the steam side enthalpy difference over the reboiler heat exchanger divided by the amount of captured CO₂. TCM is well equipped with multiple analysers and flow meters for each of the three gas flows. The present analysis is made using the same selection of analysers and flow meters as [9].

Each test was operated up to 24 hours targeting stable operation and each of the data points presented in Figure 2 to Figure 4 represent an average over typical 2 hours of stable operation within that test interval. The data quality may be affected by steam quality and moisture in the CO₂ product flow out of the stripper. For phase A and part of phase B, steam temperature into the reboiler heat exchanger was close to saturation temperature and thus introduced some uncertainty on the steam quality. It should be noted that for phase A, B and C, the measured moisture content out of the stripper fluctuated rather lively.

2.3 Results from flue gas with 10 vol% CO₂

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The energy required to capture 90% of the CO₂ from the CHP flue gas with recycling to mimic 10 vol% SMR

furnace type of flue gas was determined during phase A and B tests.

Figure 2 (a) shows SRD at 90% capture rate for phase A tests utilising 18 m packing height. During the tests the flue gas flow rate was kept constant at 48,000 Sm³/h, while the solvent flow rate was varied. The optimum steam consumption achieved for tests A5 and A1 were approximatively the same, i.e. 3.2 GJ/ton CO₂ at lowest L/G ratio around 1.9 kg/Sm³, at lean solvent flow rates 90,800 kg/h and 92,100 kg/h, respectively. Note that A1 test was conducted at 35 °C while A5 tests was carried out at 37 °C. The increase in temperature was applied to control precipitation in the absorber. As experienced from previous campaigns [4], increasing the flue gas inlet temperature has a negative effect on the SRD. However, Figure 2 (a) shows that SRD during A5 test is slightly lower than A1 test. This may be due to instability in the plant operation during A1 test and since calibration was not performed for the IR-high instrument at absorber inlet. The IR-high instrument showed higher values while the actual CO₂ concentration during A1 test was 9.5 vol% (dry). Calibration was made after the A1 test and point A5 is considered as the optimum for the phase A tests. After the B series the A5 test was repeated with an SRD of 3.3 GJ/ton CO₂. This illustrates reduced reproducibility due to minor changes in operational conditions etc.

Phase B utilised 12 m absorber packing height while maintaining capture rate at 90% as well as flue gas flow at 48,000 Sm³/h. SRD plotted against L/G ratio for tests from phase B is shown in Figure 2 (b). During the B1-1 and B2 tests, there was an issue with controlling the steam temperature and pressure to the RFCC reboiler resulting in lower CO₂ capture rate. In addition, precipitation was observed and there were frequent foaming issues in the stripper packing which led to a poor stripper performance. Several measures were taken such as increasing the flue gas inlet temperature from 37 °C to 38 °C, to be within the precipitation free zone, or even flushing the absorber sometimes to remove precipitation, and addition of antifoam to reverse the foaming in the stripper. Since the initial results of phase B tests were not satisfactory and the variation in the SRD values was small ranging from 4.0 to 4.3 GJ/ton CO₂, phase B repeat tests were carried out including two new tests B6* and B7*. B1 in Figure 2 has a low SRD but the test was at only 85% capture rate. When considering B1 (repeat), B2 (repeat), B4 (repeat), B5 (repeat), B6* and B7* tests, the SRD values were in the range 3.8 – 4.2 GJ/ton CO₂. The minimum energy penalty achieved during phase B repeat was

3.8 GJ/ton CO₂ at 113,300 kg/h lean solvent circulation rate and at L/G ratio around 2.4 kg/Sm³ during B7* test. This test series has also two more test points confirming that SRD below 4 GJ/ton CO₂ is achievable utilising 12 m absorber packing.

2.4 Comparison of absorber packing height

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Using results from phase A and phase B, the effect of packing height on energy performance when operating with SMR type flue gas (10 vol% dry CO₂) can be assessed as shown in Figure 3. Reducing the packing height from 18 to 12 m gives an increase in SRD when comparing the optimum test points, i.e. from 18 m series A5 with an SRD 3.2 GJ/ton CO₂ to the 12 m series B7* with an SRD 3.8 GJ/ton CO₂. There is also a corresponding increase in the optimum L/G ratio from 1.9 to 2.4 kg/Sm³. First of all, this illustrates that selecting a more compact absorber that can reduce CAPEX will have a consequence on the OPEX through increased heat requirement for the CO₂ stripper as well as increased pumping power for solvent circulation. Thus, a shorter absorption column may be beneficial for installations with limited space available or if low-cost thermal energy is available.

1. Results from flue gas with 15 vol% CO₂

2.5Results from flue gas with 15 vol% CO₂

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During phase C the CO₂ level in the flue gas into the absorber was increased to 15 vol% (dry) and in order to be within the design of the stripper, the flue gas flow is decreased to 34,000 Sm³/h. SRD plotted against L/G ratio for tests from phase C at 18 m packing height and 90% capture rate is shown in Figure 4. The SRD values were in the range 3.2- 3.5 GJ/ton CO₂. The minimum energy penalty achieved during phase C was 3.2 GJ/ton CO₂ at 98,400 kg/h lean solvent circulation rate and at L/G ratio around 2.9 kg/Sm³ during C7 test. The SRD level is similar to test A5 above, however, lower L/G ratios were not explored due to time constraints so the optimal case could be even further to the left of the lowest SRD value achieved from C7 test.

3.  Operational experience

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3.1 Precipitation in the lower absorber packing and mitigating actions

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According to TCM’s laboratory tests prior to ALIGN-CCUS campaign, CESAR1 solvent should not precipitate at planned absorber operation conditions [4]. However, at TCM precipitation has turned out to be a reoccurring issue with the CESAR1 solvent. The TCM absorber design is with rectangular cross-section and both temperature and concentrations may vary and create local conditions for CESAR1 to precipitate. Already during the ALIGN-CCUS campaign TCM gained knowledge under which conditions precipitation can occur, how to handle and dissolve precipitates.

Precipitation was most easily detected by increase in the pressure drop in the lower absorber packing. If larger amounts of solvent precipitate, it can also be noticed by significant decrease in the solvent concentration. At stable operation, without precipitation, the lower packing pressure drop is stable (+/- 0.1 mbar), and variations are mainly caused by changes in lean solvent or flue gas flow rates.

With precipitation two pressure drop profiles in absorber lower bed are observed:

1. Continuous fast increase of the pressure drop (100% increase in few hours).
   1. Unstable and increasing or decreasing pressure drop (+/- 1 to 2 mbar) at stable absorber operation or with slight variations of operation parameters.

During normal operation without precipitation, the four temperature sensors at the same elevation at the bottom of the lower absorber packing usually indicate a deviation of +/- 5 °C, and the temperature close to the absorber wall is higher than the other locations (unless no reaction is occurring). This deviation is most likely caused by higher local CO₂ loading and may indicate a poor distribution close to the walls in normal operation.

With precipitation the temperature sensors often indicate similar temperatures (+/- 1 °C in some cases). However, with high precipitation (pressure drop profile 1), flooding may occur on the whole packing area, causing a uniform temperature of the packing. Significant modification of the operation parameters or absorber flushing is required in order to control the pressure drop. In case of pressure drop profiles 2, an increase or decrease of the pressure drop is also observed at several tests at almost identical parameters, despite of better conditions for avoiding precipitation. This is likely caused by the local accumulation of precipitation close to the wall as the concrete absorber walls are not insulated and poor gas distribution is expected at the corners and walls.

During the start of phase A at 18 m absorber packing height, 10 vol% (dry) CO2 concentration and 90% CO2 capture rate, there was a slight increase in the differential pressure in the lower absorber bed which indicated that precipitation might be occurring. This was dealt with by increasing the flue gas inlet temperature from 35 °C to 37 °C in attempt to avoid precipitation. Although a higher flue gas inlet temperature negatively impact the steam consumption, it was prioritized to run tests at higher temperatures in order to avoid precipitation. However, towards the end of phase A tests and despite the increased temperature, the pressure drop across the lower absorber packing was increased drastically from 7 to 14 mbar indicating a significant precipitation event. An absorber flushing was required to dissolve the precipitate. This was carried out by turning off the flue gas feed blower and increasing both the lean solvent flow rate and temperature. As a result of the flush test, the differential pressure in the lower absorber bed was reduced to 7 mbar indicating that the precipitate had been cleared. The measured and the calculated pressure drop during phase A testing are shown in Figure 5 (a).

During phase C tests at 18 m packing height, 15 vol% CO2 (dry) in the flue gas and 90% CO2 capture rate, the increasing differential pressure in the lower absorber packing was a recurring issue even if maintaining a high flue gas temperature of 40 °C. Therefore, two tests were dedicated to investigating further the differential pressure rise, see Figure 5 (b). The first test was run to provoke the differential pressure to be increased. During this test, the pressure drop increased from 4 mbar to 7 mbar. In the second test the water which is usually dumped to the absorber sump from the lower water wash was led to the 3^rd water wash (the unused upper absorber bed) instead to see if this could affect positively on the differential pressure in the lower absorber bed (i.e. by contributing to diluting and flushing). However, the effect on the pressure drop was limited, and the differential pressure stabilized at 5.9 mbar as shown in Figure 5 (b).

3.2 Foaming evidence in the RFCC stripper during tests mimicking SMR flue gas

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Analyses of the stripper temperature profiles at TCM revealed that CESAR1 solvent tends to foam, and this depends on several factors that may vary in the plant operation. At times stripper profiles show that foaming may start some hours after plant start-up, even with a fresh solvent and may be increased or decreased. Operation parameters that are suspected to cause and/or influence the formation of foam are mostly not predictable or repeatable. Among these, the high stripper temperature and consequently high evaporation rate of solvent at the bottom of the stripper packing. Other potential reasons for formation of foam could be impurities in flue gas, solvent properties, particles of solids and corrosion, and design of stripper column internals.

The main consequence of foaming observed is unstable stripper operation. Hence, foaming leads to decreased stripper efficiency and thereby not allowing to achieve optimal test conditions. As foaming has a direct impact on the regenerator performance, more steam will be needed to regenerate the solvent and achieve the target CO₂ capture rate. Hence, the specific reboiler duty SRD values can increase by 0.1 GJ/ton CO₂ up to 0.25 GJ/ton CO₂ in the worst cases of foaming.

Foaming in the RFCC stripper was an intermittent issue throughout the test program particularly during original phase B tests at 12 m absorber packing height (see section 2.3). As the results from these tests were not promising due to several periods of high foaming or flow maldistribution, phase B tests were repeated to reverse the foaming issue by injecting a small amount of antifoam. Although foaming during phase B repeat and phase C was limited, a 2 liter of antifoam addition was able to remove the strong foaming tendency and led to lower steam requirements in the stripper reboiler and consequently lower energy numbers (SRD). However, the duration of antifoam effect is variable and could be limited to only a few hours.

Based on literature [10] excessive antifoam dosing is not recommended as its function can be reversed and be a foam promoter. Future CESAR1 tests at TCM may confirm the minimum injection rate and if lower injection rates at short intervals reduce the risk of excessive antifoam dosing. It is also recommended to minimize risks of local high gas flow or liquid flow in the stripper packing by ensuring a suitable vapor flow distribution from the stripper reboiler to the stripper packing.

Future CESAR1 tests might also consider testing the solvent at relevant temperature, pressure and packing with representative flue gas to be able to confirm the eventual impact of specific decomposition products to foaming. If foaming is caused by impurities or degradation products, then it could be possible that activated carbon bed operation and/or thermal reclaimer unit can help to reduce foaming tendency.

Conclusion

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The three test series (phase A, B and C) discussed above with CESAR1 solvent showed interesting results for 90% CO₂ capture from flue gases with comparable levels of CO₂ to that of a SMR furnace. At 10 vol% (dry) CO₂ the minimum SRD was found to be 3.2 GJ/ton CO₂ when utilizing 18 m absorber packing. For the same flue gas conditions

but with absorber packing height reduced to 12 m, the minimum SRD became 3.8 GJ/ton CO₂. This test series has two more test points confirming that SRD below 4 GJ/ton CO₂ is achievable with only 12 m absorber packing. The 18 and 12 m cases with 10 vol% CO₂ illustrate the consequence of utilizing a more compact absorber that reduces capex at the expense of increased heat requirement for the CO₂ stripper. The third test series was operated at 18 m absorber packing with CO₂ in flue gas increased to 15 vol% CO₂ (dry). Similar SRD level as the corresponding 10 vol% CO₂ case was found. However, the minimum SRD was likely not demonstrated since the point where SRD stops decreasing when decreasing L/G had not been reached.

During the test program there was precipitation in the lower absorber packing in spite of that the conditions in the absorber should not be favorable for this to occur. Precipitation was mitigated by increasing the flue gas inlet temperature and flushing of the absorber was also required. The cause may be related to the absorber design and local zones with poor gas distribution at lower temperature close to the absorber walls as well as corners. Foaming was observed in the stripper and introduced unstable stripper performance and less efficient stripping. Injection of anti- foam reduced the foaming tendency, but the effect was temporary. Better understanding of the onset of precipitation and foaming should be included in future CESAR1 tests at TCM.

The basis for this investigation is Equinor’s SMR unit at Tjeldbergodden methanol plant which is the largest methanol plant in Europe. The test campaign provides value to the industry as it helps to reduce both technical and financial uncertainty associated with CO₂ capture. The campaign results give an indication on what SRD values one might expect when operating a CO₂ capture plant.

Acknowledgments

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The authors gratefully acknowledge the staff of TCM DA, Gassnova, Equinor, Shell and TotalEnergies for their contribution and work at the TCM DA facility. The authors also gratefully acknowledge Gassnova, Equinor, Shell, and TotalEnergies as the owners of TCM DA for their financial support and contributions.

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